EUROPEAN COMMISSION

Brussels, 19.10.2011 SEC(2011) 1233 final

COMMISSION STAFF WORKING PAPER

Impact assessment

Accompanying the document

Proposal for a

Regulation of the Europen Parliament and of the Council

on guidelines for trans-European energy infrastructure and repealing Decision No 1364/2006/EC

{COM(2011) 658 final} {SEC(2011) 1234 final}

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TABLE OF CONTENTS

Background and policy context............................................................................................................ 3 1. Procedural issues and consultation of interested parties.................................................. 3 2. Context.................................................................................................................................. 8 3. Problem definition ............................................................................................................... 9 4. Baseline scenario ................................................................................................................ 18 5. Key players and affected population................................................................................ 22 6. EU right to act .................................................................................................................... 22 7. Objectives ........................................................................................................................... 23 8. Policy options...................................................................................................................... 25 9. Analysis of impacts ............................................................................................................ 36 10. Comparison of policy options ........................................................................................... 48 11. Monitoring and evaluation................................................................................................ 50 Annex 1 Glossary................................................................................................................................. 52 Annex 2 Input documents................................................................................................................... 53 Annex 3 results from the public consultation on permit granting .................................................. 57 Annex 4 Outcome of stakeholder consultation among transmission system operators ................ 65 Annex 5 Energy infrastructures priorities ........................................................................................ 68 Annex 6 Typical project development process for an energy infrastructure project and examples

of projects having faced permit granting delays .............................................................................. 69 Annex 7 Key data on permit granting procedures in selected Member States.............................. 72 Annex 8 Main reasons for public opposition to energy infrastructure projects............................ 73 Annex 9 National electricity and gas market statistics .................................................................... 74 Annex 10 Elements of national regulatory frameworks for electricity and gas infrastructure ... 80 Annex 11 Project case studies concerning regulatory and financing issues................................... 82 Annex 12 Externalities faced by energy infrastructure projects .................................................... 86 Annex 13 Financing context for gas and electricity infrastructure ................................................ 88 Annex 14 The current regulatory framework for infrastructure delivery .................................... 92 Annex 15 Past and future infrastructure development in the EU .................................................. 98 Annex 16 Evaluation of suboptions with regard to permit granting and public consultation ... 111 Annex 17............................................................................................................................................. 116 Challenges and corresponding measures proposed........................................................................ 116 for permit granting and public involvement................................................................................... 116 Annex 18 Administrative cost assessment....................................................................................... 118 Annex 19 Impact of a 2% equity adder on transmission tariffs ................................................... 122

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BACKGROUND AND POLICY CONTEXT This impact assessment is prepared to support the forthcoming legislative proposal on energy transmission infrastructure for the EU, which will replace the existing legal framework for Trans-European Energy Networks (TEN-E). The Commission adopted in November 2010 a “Communication on energy infrastructure priorites for 2020 and beyond”, supported by an impact assessment, confirming the need to revise the existing policy and financing framework, identifying nine priority corridors/areas to be implemented by 2020 and proposing a new method to identify projects of common interest (PCIs) to implement these priorities. The Commission's approach was largely endorsed by the February 2011 European Council. In June 2011, a Commission Staff Working Paper for the Energy Council assessed in detail the investment needs and obstacles for the coming decade. This impact assessment builds on the findings and conclusions of the above-mentioned documents and provides a more in-depth analysis concerning possible measures for permit granting, regulation and financing of energy infrastructure. The upcoming legislative proposal will confirm the identified infrastructure priorities and establish rules for selection of projects of common interest as well as their implementation through permit granting, regulatory and whilst financing measures will be addressed in the proposal for a Connecting Europe Facility. Out of the pool of projects of common interest, a limited number of projects will be chosen for funding under the proposed Connecting Europe Facility (CEF), which the Commission proposed in June 2011 for the next multiannual financial framework (2014-2020) and which covers energy, transport and digital infrastructure. The CEF will be dealt with under a separate regulation and impact assessment. The general principles for financing and the criteria for eligibility of projects of common interest to CEF funding will be provided for in this proposal, while the CEF regulation will specify the selection and award criteria. It should be underlined that for the purpose of presenting and assessing the full range of possible measures with regard to infrastructure development, this impact assessment also addresses financing options, even if their translation in policy measures will take place in the CEF.

1. PROCEDURAL ISSUES AND CONSULTATION OF INTERESTED PARTIES

Identification: Lead DG: DG ENER; Agenda planning/WP reference: 2011/ENER/XXX

1.1. Organisation and timing

Between March and September 2010, a first impact assessment1 ("the 2010 impact assessment") was prepared for the Communication "Energy infrastructure priorities for 2020 and beyond – a blueprint for an integrated European energy network"2 ("the November 2010 Communication"), which was adopted in November 2010.

The work for this impact assessment started in November 2010. The various parts of the problem definition were discussed with the Impact Assessment Steering Group (IASG) in three meetings between February and May 2011. The policy options and impact analysis were presented to the IASG in late June 2011 and the draft final IA in early July. Services involved in the Impact Assessment Steering Group were: AGRI, DEVCO, BEPA, BUDG, CLIMA, COMP, ECFIN, EEAS, ELARG, EMPL, ENTR, ENV, ESTAT, HOME, INFSO, JUST, JRC, MARE, MARKT, MOVE REGIO, RTD, SANCO, SJ, SG, TRADE, TAXUD

1 SEC(2010) 1395 2 COM(2010) 677

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1.2. Consultations and expertise

1.2.1. Public consultations

Several specific consultations have fed this impact assessment. As early as November 2008 the Second Strategic Energy Review launched the Green Paper "Towards a secure, sustainable and competitive European energy network"3 on the TEN-E revision. Among respondents from the energy industry consensus emerged on the need for a fundamental review of the TEN-E, for the EU to better align the energy network policy and the EU energy and climate policy targets, to provide for a stable regulatory framework, coordination and raising public acceptance. The respondents identified complicated administrative procedures, diverging regulatory regimes across local authorities and national borders as well as local resistance as the main barriers. The absence of a specific legal remit at EU level to mitigate these obstacles was acknowledged. The role of the EU in facilitating infrastructure projects in third countries was welcomed, and the importance of external energy relations to infrastructure policies was reaffirmed.

Following the November 2010 Communication, a public consultation on permit granting took place between March and April 2011. The majority of the 80 respondents favours the introduction of binding time limits (60%) as well as a "one-stop-shop" approach (79%) for energy infrastructure projects.4 To further increase transparency of the permit granting process guidelines for an earlier involvement of the public were considered helpful. This includes better communication of the economic and social benefits of projects, through promoters and authorities, as well as the early and full provision of environmental information. Regarding compensation measures, half of the respondents believed that here competency should remain with the MS and opposed a harmonization on EU level. More detailed results are presented in Annex 3.

A public consultation led by ECFIN was also carried out during the same period concerning the EU 2020 Project Bonds Initiative. More than 130 stakeholders from financial institutions, government bodies, infrastructure development, manufacturing, and research, the insurance and legal sector submitted their contributions. The initiative was considered useful by most of them. 60% considered that the bond mechanism is likely to attract private sector institutional investors to the sectors of transport, energy and ICT. A further 16% expected its success to be dependent on technical features of the mechanism (price, structure, attracted rating, etc.). Views on the project size appropriate for bond funding varied widely, but it emerged that the instrument is likely to be suitable for bigger investments with a minimum size of EUR 50 to EUR 250 million.

1.2.2. Surveys, workshops and studies

Targeted questionnaires on permit granting and financing have been sent to the main stakeholders: ENTSOs in electricity and gas, GIE, national regulators and financial institutions (notably the EIB). Results from this consultation can be found in Annex 4.

A series of four workshops took place with regulators between February and June 2011 to discuss investments needs, cost allocation and financing. A workshop was jointly organised with the Florence School of Regulation in May 2011 to discuss cost allocation issues with academics and energy experts. All relevant issues have also been presented to and discussed with other stakeholders such as industry associations or NGOs. Two workshops were also held for Member States in May and June 2011 to present and discuss options for selection of projects of common interest and permit granting measures. The working group meetings of the Baltic Energy Market Interconnection Plan (BEMIP – electricity and gas), the North Seas Countries Offshore Grid Initiative (NSCOGI – electricity) and the North-

3 COM(2008)782 launched the public consultation between 13/11/2008 and 31/03/2009. The Commission received

91 written replies to the Green Paper. 13 came from Member States (2 from a regional and a local government), 1 from regulators, 60 from the industry, 2 from academia and 13 from individual citizens, NGOs and other organisations. See http://ec.europa.eu/energy/strategies/consultations/2009_03_31_gp_energy_en.htm for details.

4 Approximately 20 % did not express a clear preference.

http://ec.europa.eu/energy/strategies/consultations/2009_03_31_gp_energy_en.htm

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South Interconnections High Level Group for Central Eastern Europe5 (electricity, gas and oil) offered platforms to discuss the regional aspects of infrastructure development.

In addition, the Commission used external expertise provided through two consultant studies on permit granting and financing carried out in the period January to May 2011.

1.2.3. Other consultations

A high level conference under the Hungarian Council presidency on energy infrastructures took place on 16th and 17th May 2011, where Member States administrations, network operators, regulators and other stakeholders were given the opportunity to discuss the various proposals of the Commission. Discussions also took place at the Gas Coordination Group (March and May 2011), the Madrid (March 2011) and Florence Fora (May 2011) and at the relevant working group meetings of the Berlin Fossil Fuels Forum. Consultations with individual Member States have been ongoing on a continuous basis.

1.3. Opinion of the IAB

IAB opinion Changes made

(1) Improve overall coherence with related policies

The report should better describe how this initiative relates to the overriding Connecting Europe Facility and other EU initiatives such as the Project Bonds Initiative. In particular the report should ensure greater coherence and consistency with these related initiatives in terms of synergies, underlying market/regulatory failures, evaluation of results and project selection. The approach to financing modalities should be clarified.

The relation between this initiative and the CEF is now described in great detail in Section 7.3.

The problem definition should be enhanced by a better description of the wider context of the need for investment of public funds in energy infrastructure in particular by highlighting underlying problem drivers such as the market failure aspects.

The 2010 IA described in detail the overall investment needs and the project categories facing particular regulatory and market failures justifying the use of public funds. Annex 12 of this IA refines the analysis of these externalities. The IA accompanying the Regulation for the CEF discusses the need for public funds further. Section 2.2 of the 2010 IA made a detailed presentation of the current TEN-E financing framework in the context of major future investment needs and related externalities and its shortcomings (notably insufficient resources; limitation to electricity and gas infrastructure; lack of focus; rigid list of targeted projects without top-down identification of priorities; insufficient coordination with other EU funding

5 This High Level Group was set up in early 2011 to promote the implementation of energy infrastructure projects

and improve security of supply and market development in the region. It includes representatives from Bulgaria, the Czech Republic, Hungary, Poland, Romania and Slovakia, and Croatia as an observer.

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programmes). Section 3.3.3 of this IA explains them again. The introduction of the problem definition chapter has also been strengthened in this regard.

Greater clarity concerning the content of the proposed legal instrument should be provided and the report should better explain why this Impact Assessment focuses mainly on problems relating to permit granting, regulation and financing.

The proposed Regulation will focus on the identification of projects of common interest and measures for these projects in the fields of permit granting, regulation and financing, which is why the analysis in this IA is focused on these issues. Section 7.3 explains the content of this initiative further and establishes the link with the other proposals.

(2) Strengthen the subsidiarity analysis and option design

The report should much better explain and justify, in terms of the principles of subsidiarity and proportionality, the need for EU level measures relating to time limits and other process and structural changes (such as 'one stop shops') to Member States' procedures for granting permits for energy infrastructure.

The description of the policy options has been complemented with an analysis of the measures with respect to the principles of proportionality and subsidiarity, and the identification of the preferred options has been more thoroughly justified in light of this analysis, stakeholder views, and the effectiveness of measures with regard to the overall objective of the proposal.

In relation to regulatory problems, the report should better explain the need for EU measures on cost allocation and tariff setting.

The business as usual scenario now has been adapted with a detailed analysis on why this is a not option and where the internal energy market rules should be complemented by new rules on cost allocation and incentives in the tariff systems and regulatory framework.

The report should discuss and underpin with adequate evidence the assumption that all identified problems, including those of an environmental nature, can be solved in an appropriate manner by a more centralised approach/procedure.

The description of the Policy Option A.2 has been extended to explain how a centralised approach would adequately address the issues at stake, particularly with regard to environmental procedures.

The presented options should be better explained and justified and more nuanced options, such as soft law, considered in greater depth.

The policy options have been explained in more detailed where necessary, particularly policy option A.1. A more nuanced suboption with respect to the establishment of time limits has been created, which is, due to constraints in text length, assessed in detail in Annex 16.

The logical flow between the identified problems on the one hand, and the proposed policy options/measures on the other, should be much more clearly established (such as the impact of changes to permitting rules on public acceptance).

A table illustrating how the proposed measures solve the identified problems has been included in Annex 17.

The report should integrate and fully address different stakeholders' views on these key points.

The report was complemented by a more detailed description of stakeholder views in the context of the proposed policy options, and explanations were provided how these have been taken into account in the selection of the policy options. A more detailed summary of the consultation on permit granting procedures has been provided in the Annex.

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(3) Improve the assessment of impacts

The report should provide a more in-depth assessment of the impacts of the options on stakeholders including Member States and citizens particularly in relation to existing rights regarding planning.

The assessment of impacts of policy options A.1 and A.2 on stakeholders with regard to existing procedures provides more details on how Member States' authorities and citizens would be affected.

The report should include a more comprehensive analysis of the legal implications of the preferred policy options concerning permit granting, which should be followed-up in the discussion of economic implications. In particular, the report should clarify the legal implications (e.g. creating a precedent, impact on other legislation) of the introduction of a Lex Specialis clause for Projects of Common Interest.

The report provides highlights in more detail that legal implications on Member States are expected to be relatively limited for the mandatory measures foreseen. However, the information needed to provide an analysis on each of the 27 EU Member States' legal frameworks is not available, and can therefore not be included in this report. The description of the legal implications in terms of the Lex Specialis with regard to the creation of a precedent and impact on the Waterframework Directive has been extended. The compatibility with the EU acquis will nevertheless remain subject to scrutiny of the Legal Service as part of the interservice consultation.

In terms of time limits the report should assess in greater depth the impact of such limits on the fulfilment of all legal requirements, including for public consultation. Furthermore the report should assess the impact of such time limits in countries where the current timeframes for awarding permits are significantly longer than the four years proposed and possible spill-overs to other infrastructure projects.

A more detailed analysis of the impacts of the time limits has been provided for policy option A.2. An illustrative overview of how the time limits and other measures foreseen accommodate existing procedures, i.a. established by environmental legislation, is provided for under policy option A.3.

Summaries of relevant findings from assessments of impacts in earlier, related IA reports should be included in the report. The report should better explain the reasons for choosing options judged to be difficult to implement (such as for example the ex ante cost allocation mechanism).

The results from stakeholder consultations have been added in the description of the regulatory options and the business as usual scenario provides for the justification of the choice of options made.

In all regulatory options the views of stakeholders have been added, in particular the preferences and design options as well as likely impacts with regard to their implementation. The ex-ante cost allocation method will provide for a cost allocation principle and a framework for a joint decision by NRas concerned on the cost allocation negotiations, with the involvement of ACER in case of disagreement.

(D) Procedure and presentation

The report should provide much greater transparency of the extent of stakeholder consultation and should better reflect the comments of all stakeholders on all major points

The views of stakeholders on the main issues of the proposal have been integrated in the text, and are particularly discussed in the context of the

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throughout the main text. It should be clearer as to the extent that stakeholders and Member States have been consulted on the specific set of options assessed in this report.

policy options proposed.

2. CONTEXT The November 2010 Communication built on an impact assessment, which covered the development of energy infrastructures for the period 2010-2020 with a view beyond to 2030. It assessed investment needs for new transmission infrastructure, evaluated the current TEN-E framework and financing possibilities and compared various policy options for implementing sufficient infrastructure to support the achievement of the EU's energy and climate policy goals in the most cost efficient way. The impact assessment analysed the design of a new policy instrument to replace the current framework and expressed preference for broad priority corridors complemented by smart and transparent criteria for identifying projects of common interest (PCIs) at EU level, thereby building on existing regional cooperation initiatives.

It also quantified the total investment need at about EUR 200 bn between 2010 and 2020 and identified two major categories of obstacles related to permit granting and regulation and financing. Based on a top-down estimation, it valued the projects subject to these obstacles and therefore at risk of not being delivered to approximately EUR 100 bn (also called "investment gap").

The November 2010 Communication accordingly proposed nine strategic priority corridors for the period up to 2020 and two longer-term priorities (see Annex 5), as well as a new approach to identifying, selecting and implementing projects of common European interest, including through measures in the field of permit granting, public consultation and regulation..

Both the 4 February 2011 European Council and the 28 February 2011 Energy Council endorsed the priorities proposed by the Commission and expressed support for the Commission’s approach to implement these priorities, notably concerning criteria for PCI selection. The Commission presented, in a Staff Working Document6 to the June 2011 Energy Council, a refined analysis on investment needs, investments at risk of not being delivered, and measures proposed to respond to the financing requirements and overcome the obstacles identified.

On 29 June 2011, the Commission adopted the Communication "A Budget for Europe 2020" on the next multiannual financial framework (2014-2020)7, which proposes the creation of a Connecting Europe Facility to promote the completion of priority energy, transport and digital infrastructures with a single fund of EUR 40 billion, out of which EUR 9.1 bn are dedicated to energy.

In July 2011, the European Parliament expressed strong support for the Commission's proposed priorities, project selection method and specific implementation measures8. Concerning the next multiannual financial framework, it came out in favour of using the EU budget to promote the development of energy infrastructures and optimizing the use of the budget to support the Europe 2020 headline targets9. The Committee of the Regions also supported in July 2011 the Commission's approach and suggested the preparation of a corresponding detailed financing plan10.

Building on the 2010 impact assessment, a complementary, more detailed impact assessment is now being presented for the legislative proposal following up on the EIP. It analyses policy options in the fields of permit granting / public consultation, regulation and financing that should apply to projects of

6 SEC(2011) 755 7 COM(2011) 500/I final and COM(2011) 500/II final (Policy Fiches) 8 European Parliament resolution of 5 July 2011 on energy infrastructure priorities for 2020 and beyond

(2011/2034(INI)) 9 European Parliament resolution of 8 June 2011 on Investing in the future: a new Multiannual Financial Framework

(MFF) for a competitive, sustainable and inclusive Europe (2010/2211(INI)) 10 CoR 7/2011 rev. 2 – ENVE-V-010

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common interest selected for implementation of the defined 2020 infrastructure priorities. For each of the various obstacles identified, it assesses available, effective and cost-efficient solutions.

This impact assessment does not discuss again the identification of energy infrastructure priorities and the choice of criteria for PCI selection to implement these priorities as these issues have been analysed in the 2010 impact assessment, presented in the November 2010 Communication and further refined since with all relevant stakeholders. In line with the outcome of the 2010 impact assessment and as already specified in the November 2010 Communication, the Commission has defined simple and transparent criteria to ensure the selected projects of common interest contributes effectively to the implementation of the identified energy infrastructure priorities.

Nor does it analyse the scope of the new policy to be developed, as this was the subject of the 2010 impact assessment, which concluded that oil and carbon dioxide infrastructures should be included in addition electricity and gas infrastructures, which are already covered under the current TEN-E policy.

As a result, the infrastructure priorities form the scope of this impact assessment and the upcoming initiative. The sectors covered by the priorities are electricity transmission, storage and smart grids, gas transmission, storage and LNG/CNG, as well as transport of carbon dioxide and oil. The projects covered are all those projects with European significance, i.e. projects with a significant cross-border impact affecting at least two Member States.

The general options regarding financing of projects of common interest are discussed in this IA for the purpose of presenting and assessing the full range of possible measures with regard to infrastructure development. However, the precise problems related to EU financing, notably with regard to investment leverage and project implementation, are also discussed in the impact assessment accompanying the Regulation for the CEF. This treatment of financing questions in both impact assessments is justified, as this initiative will define the eligbility criteria for financing of infrastructure projects under the CEF, while the Regulation for the CEF will provide for award criteria and the various types of financial assistance (grants and innovative financial instruments) available for selected projects.

3. PROBLEM DEFINITION The 2010 impact assessment explained the wider context of the need for private and public investment in energy infrastructures and highlighted in particular the scale change in both investment volumes and investment delivery times necessary to deliver about EUR 140 bn worth of investments in onshore and offshore electricity networks, including smart grids11, and about EUR 70 bn in gas networks of European significance, as well as EUR 2.5 bn for the construction of CO2 transport infrastructure by 202012. Investment volumes for period up to 2020 will, based on TSO forecasts, increase by 30% for gas and 70% for electricity compared to current levels13. Compared to the period 1989-2003, the needed annual investment in electricity transmission will even have to double14. This investment challenge and urgency clearly distinguishes energy infrastructures from infrastructures in other sectors, as energy networks are a precondition for reaching the 20-20-20 targets.

These estimations did not take account of maintenance, refurbishment or new investment expenses for national transmission networks without European significance or for distribution networks, nor of investments necessary for the period after 2020. The impact assessment highlighted that the identified European infrastructure priorities will represent a significant share of the investment needs. These

11 In Europe, over EUR 5.5 bn have been invested in about 300 Smart Grid projects during the decade 2000 to 2010.

Only about €300 million has come from the EU budget, mainly through Framework Programme funding. About EUR 70 million are foreseen under the Framework Programme for the period 2012/2013 on smart grid topics, while another EUR 75 million have been committed for investments in R&D for smart cities and communities. Nevertheless, the actual deployment of Smart Grids in Europe is still at an early stage.

12 See SEC(2010)1395 for more detail on the figures and the uncertainties attached to them. 13 Roland Berger, 2011a. 14 SEC(2010)1395. Note also that the 2006 inquiry into the European Gas and Electricity Sectors underlined that

"Amounts invested in cross-border infrastructure in Europe appear dramatically low. Only 200 million € yearly is invested in electricity grids (…)."

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numbers have in the meantime been largely confirmed by national regulators and exceeded by estimates from transmission system operators15. The 2010 impact assessment also estimated that the full delivery of the needed infrastructure would have significant positive overall effects on GDP and employment compared to BAU, with a cumulative effect of +0.42% of GDP and 410,000 additional jobs over the period 2011-202016.

The security of new and existing energy infrastructures, as a key element to ensure their integrity, reliability and climate resilience are important parts of the EU's energy policy. Infrastructure security is the subject of a specific, complementary policy called the European Programme for Critical Infrastructure Protection (EPCIP). Given the possible impacts of events related to climate change such as storms, floods, heat and droughts, climate proofing of existing and even more so new infrastructures is equally important17. Present and future critical energy infrastructures will need to comply with existing legal instruments18 in view of implementing the physical and operational measures to achieve a high level of security – including cyber-security – against malicious acts. Other risks, such as those related to natural hazards may also be addressed within this policy and other specific instruments in the area of safety. The measures necessary to mitigate these risks will create additional investment needs, which are part of the network operators' core duty of ensuring safe, secure and reliable transmission of energy. They are not specifically addressed in the following, as they can only be assessed by relevant actors in the spatial planning and development process for one or several projects.

3.1. Problems related to permit granting procedures and public involvement for energy infrastructure projects

Lengthy and ineffective permit granting procedures, along with public opposition, are amongst the major reasons impeding the timely implementation of energy infrastructure projects, in particular electricity overhead lines. The time from start of the process to final commissioning of a power line19 is frequently more than ten years, and the commissioning of a project which faces substantial public opposition can even take longer (see Annex 6 for project examples). This is of particular concern in view of the massive investments in electricity transmission necessary up to 2020 and the according number of permits to be granted20. In the context of a survey to which 24 TSOs responded, 16 identified difficulties related to the administrative permit granting procedure and 21 identified public opposition as relevant reasons for delays in the implementation of electricity infrastructure21. Results of another survey amongst TSOs of 13 MS showed that public opposition was considered as the most important potential cause for delays (rating: 5.2 of 6 points), followed by complex permit granting procedures (rating: 4.5 of 6 points)22.

15 See SEC(2011)755 for more detail. 16 The impact of developing an offshore grid would be particularly positive in this regard. A case study on

Bremerhaven on the German North Sea has shown that companies in the city have attracted about EUR 250 million and created some 700 new jobs in the period 2006-2009 (Source: EWEA, "Oceans of Opportunity", September 2009).

17 Impacts of climate change and extreme weather events have shown to disrupt energy services (with significant costs to the economy). According to the IAEA, about half of the system faults in electricity grids are caused by weather effects. Adapting energy infrastructure, including transmission lines, to these effects could, according to the literature available to date, entail significant costs (see for example Vattenfall Europe (2006); Van Ierland, E.C. et al. (2007); ADAM project (2009); US National Research Council (2010)). Despite these first studies allowing an initial discussion of the issue, its specific relevance for transmission infrastructure needs to be further assessed, based on more evidence.

18 Council Directive 2008/114/EC of 8 December 2008 on the identification and designation of European critical infrastructures and the assessment of the need to improve their protection

19 The major phases of a typical project development process in electricity are presented in Annex 6. 20 One example is the offshore grid development in the Northern Seas: According to ENTSO-E, it could lead to about

250 offshore cables needing onshore landing points between now and 2030. It should however be noted that planning and permit granting procedures are different for onshore and offshore installations, the detail and amount of environmental and socio-economic spatial data used, the number of possible planning solutions and the time it takes to involve all stakeholders being usually higher on land than at sea.

21 Acknowledging these problems, TSOs and NGOs have formed an alliance to find solutions (Renewables Grid Initiative and Smart Energy for Europe Platform), and some Member States have already introduced legislation to facilitate procedures (such as UK, IE, NL, DE).

22 Roland Berger study on permit granting procedures, 2011.

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The two main drivers causing the long delays will be examined in the following sections: 1. Inefficient administrative procedures, notably with regard to the organisation of the

procedures, and the conduct and competences of involved parties; 2. Opposition of affected population

3.1.1. Inefficient administrative procedures

• Complex and fragmented process: Although the stages of the permit granting process are generally similar in different Member States, the concrete procedures within one phase differ highly from one country to another, and often also between the different regions within one country, particularly in those countries with federal structures where planning competence is at regional level (Austria, Belgium)23, which makes cross-border projects even more of a challenge. Furthermore, permit granting processes are also generally of extremely fragmented nature. There are typically many authorities indirectly whose opinion is required in the process. their number can reach up to 50 per project. The number of authorities directly involved, i.e. responsible to issue constitutive, legally-binding permits, is usually lower, ranging between one and more than ten (for data see Annex 7). If responsibility for the delivery of the permits is spread over several authorities, this leads to difficulties in identifying responsibilities, different interpretation of laws, inconsistencies in the handling of procedures, friction losses and duplication of work.

• Lack of upfront planning and coordination: It is in many Member States up to the promoter to plan the process and coordinate the different bodies and permits, with limited guidance from public administrations. However, due to lacking managerial resources and competences of promoters, coordination activities are often inefficient. Lack of appropriate upfront planning and coordination procedures has particularly severe consequences for cross-border projects, where delays on one side of the border can significantly impede progress on the other side. Such procedures are also crucial for wind offshore infrastructure projects, which often span large areas such as entire regional seas. Acknowledging the benefits of an effective upfront maritime spatial planning, the Commission is at present carrying out an impact assessment.

• Lack of time limits: In many Member States there are no binding time limits in place to ensure that decisions are taken in a timely fashion. In 13 MSs there are time limits for the entire procedure and/or its individual stages. However, in many MSs these are not always respected as enforcement mechanisms are not applied or do not exist. Surveys show that the permit granting process (i.e. pre-application efforts and statutory administrative procedure) has an average duration of between four and ten years (see Annex 7 for details). Adding about three years for first planning efforts and construction, this leaves an average duration of 7-13 years24.

• Unclear documentation standards and lack of quality: Specific difficulties arise in the pre-application phase, when usually only limited information is available regarding the elements to be analysed and submitted with the application, and when promoters hand in application documents of poor quality. This leads to cumbersome and lengthy request-response cycles between promoters and authorities, particularly when deadlines for additional requests are missing.

• EU legislation25 and national legislation have set high standards for environmental protection, which has been perceived as a major challenge by promoters during the past years. This legislation is not leading to delays per se, nor does it prevent projects from taking place, but the lack of coordinated implementation by national authorities has posed major difficulties for promoters, as the fulfilment of requirements is often time consuming and can, if not implemented adequately,

23 Germany adopted a law in 2011 to shift planning competence from the state to the federal level

(Netzausbaubeschleunigungsgesetz – NABEG). 24 Judicial procedures are not included in this time frame. To be noted that for complex cross-border projects the

duration tends to exceed the average duration. 25 Directive 2001/42/EC on the assessment of the effects of certain plans and programmes on the environment;

Directive 85/337/EEC on the assessment of the effects of certain public and private projects on the environment; Directive 92/43/EEC on the conservation of natural habitats and of wild fauna and flora; Directive 2009/147/EC on the conservation of wild birds; Directive 2000/60/EC establishing a framework for the Community action in the field of water policy

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lead to delays in the process. A comprehensive analysis of impacts on the environment may – depending on the available data for the specific site concerned – take one year or more as a whole vegetation period or two migration seasons have to be analysed. Particular difficulties arise if the assessment of the implications for the site or the status of a water body is negative, and if there are no alternative solutions available, as construction is in this case only allowed if the project is granted the status of overriding public interest by the national competent authority and if adequate compensation measures are taken, such that promoters face uncertainty whether a project can eventually be carried out. This issue is particularly relevant in MSs with large and scattered parts of land designated as Natura2000 habitats26, and in border regions, which are often along natural barriers of environmental significance (e.g. Pyrenees along the ES-FR border, coastal areas).

3.1.2. Opposition of affected population Opposition by landowners, citizens living in the vicinity of potential installations and stakeholder organisations poses the most significant impediment in the permit granting process. This is particularly true for Western MSs, where citizens seem to be more sensitive to (perceived) environmental and visual impacts, but it is increasingly the case also in new MSs. Public opposition usually leads to numerous objections during consultations (up to 20.000) which have to be answered by authorities and/or promoters, leading to significant additional efforts and delays in the process. Complicated and lengthy negotiations with landowners may also lead to delays at the stage when the developer needs to obtain the right to use the land in order to start construction. Lodging appeals to courts is another means of public reaction preventing the start of construction. In some countries, court appeals are possible at any time throughout the permit granting process and beyond (e.g. AU, IT), delaying the process even further. There is usually less opposition to offshore projects as citizens are not directly affected by installations. However, strong resistance of citizens living in the vicinity of landing points can prevent the timely connection of wind farms. The main reasons for public opposition, notably unclarity about the added value of a project, real or perceived impacts on the environment and landscape, health and safety concerns, and late and insufficient involvement of the public and stakeholders are presented in Annex 8.

3.2. Problems related to the regulatory framework for energy infrastructure investments Electricity and gas transmission are regulated sectors with costs for network investment, operation and maintenance recovered through tariffs fixed by national regulation, which differs from MS to MS (see Annex 9 and 10 for statistics and relevant elements of the regulatory framework concerning EU electricity and gas markets and networks). In most MSs, cost recovery for projects is based on verified national market needs and cheapest available solutions, in order to ensure cost-efficiency and keep tariffs low for national consumers27. The existing framework is therefore not geared towards delivering the identified European infrastructure priorities in view of further integrating the European energy networks and meeting the European climate and energy objectives.

It should also be noted that the commercial viability and hence the "bankability", i.e. capacity to attract commercial financing, of infrastructure projects is intrinsically linked to the regulatory framework. Infrastructure operators and investors have repeatedly called for a stable and incentivising regulatory framework with adequate long-term signals, notably for cross-border investments. The way, in which investments costs and risks are treated, directly determines the return and hence influences the incentive to invest or to lend money for a project. At the same time, changing conditions in capital markets can influence regulation for such investments (see also section 3.3).

The three main shortcomings with regard to the regulatory framework, which hinder cross-border infrastructure investments, are described in the following. Examples of electricity and gas infrastructure projects subject to regulatory difficulties are given in Annex 11.

26 E.g. 30% in the case of Slovenia. 27 Transmission tariffs account on average for only about 5-10% of household electricity prices across EU MSs.

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3.2.1. Asymmetric benefits and externalities With national energy networks becoming both more decentralised and increasingly interdependent, cross-border projects between at least two – isolated or well-interconnected – Member States or projects in one MS with significant cross-border impact multiply, which either feature an asymmetric distribution of costs and benefits among beneficiaries, or offer externalities not appropriately internalised by either market signals or the existing regulatory system. These two categories partly overlap, as many of the externalities discussed also have a cross-border, supranational dimension.

Concerning asymmetric impacts, a new internal electricity line can benefit the origin country by reducing its internal congestions, but also border countries by increasing transits. A gas reverse flow infrastructure on the territory of one Member State can be for the sole benefit of its neighbour, if the latter has only a single other gas supply route. Similarly, a new cross-border line (e.g. Austria-Italy in electricity, Hungary-Slovakia in gas) can de facto permit to increase transit for both the immediate neighbours and third countries, which are indirect beneficiaries.

As a result, internal as well as cross-border investments can positively impact the functioning of third country networks, without any explicit participation from the concerned network operators to the incurred investment cost28. This leads to a significant problem of free riding due to the asymmetry between benefit distribution and cost allocation29. In gas, the investment risk for new transmission networks is moreover strongly linked to the upstream and downstream commitments.

In addition, the more MSs are interconnected with each other, the more the identification of benefits can be complex and difficult to predict. Indeed, the benefits of a new electricity line on the territory of two MSs but benefiting several others indirectly can be very difficult to predict for the indirect beneficiaries, as these benefits depend on various factors such as long term price differentials, which themselves are influenced by a large set of parameters (generation mix in the exporting and importing country, support schemes for renewables, future other transmission lines). Given these uncertainties, benefits and revenues might not be quantifiable at all ex ante.

Today, there is no common European or region-specific framework for benefit identification and cost allocation. For more complex projects, this absence has often led to complex and lengthy decision-making negotiations between individual operators and national regulatory authorities or even made certain projects impossible to realise30. More specifically for gas, the lack of transparent, timely and efficient coordination across borders creates uncertainty to market participants and risks for network operators31. Under today's narrow framework, operators today have few incentives to develop cross-border investments when benefits go to another area.

Concerning externalities, they are positive or negative impacts provided by a given infrastructure investment, which are not properly reflected by existing market signals and revenue streams, i.e., in the case of regulated grids, transmission tariffs and, in electricity, congestion rents32. In some cases increasing the capacity or the electricity grid to the optimum level even decreases the congestion rents. While the socio-economic benefit, notably at regional or EU-wide level, of a project providing such externalities would outweigh its cost, the investment will not take place if it is based on a merely corporate based commercial viability evaluation or on optimising national interests in one MS. The

28 In its draft position paper on cost allocation, CEER calls these benefits “commercial externalities”. 29 Cf. Glachant and Kalfallah, 2011 30 The Kriegers Flak project is an excellent example: It initially envisioned the development of three wind farms

within German, Swedish and Danish waters, linked by a combined offshore grid connection, which would also serve as an interconnection between the three countries. The three-country solution has in the meantime been abandoned with Sweden's withdrawal, and the development of the project has been delayed because of regulatory challenges, despite EUR 150 million of EU funding received in the context of the European Energy Program for Recovery.

31 The 2006 sector inquiry had already outlined that on certain borders, long-term pre-liberalisation gas transmission capacity reservations still exist despite the ruling of the European Court of Justice that such reservations are not compatible with EC law, unless they were notified under Directive 96/92/EC.

32 In its draft position paper on cost allocation, CEER calls the externalities discussed under this category “non commercial externalities”.

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main categories of externalities were already discussed in the 2010 impact assessment and are further detailed in Annex 12.

3.2.2. Lack of appropriate regulatory incentives and long-term signals to meet EU priorities Compared to the European infrastructure priorities and the EU's energy and climate policy objectives, such as the 20-20-20 targets for 2020 or the 80-95% emission reduction objective for 2050, the existing regulatory framework does not give appropriate incentives and long-term signals for the implementation of all projects necessary to meet these priorities. NRAs have so far not sufficiently taken account of the corresponding investment challenge for networks up to 2020 and beyond and their specific responsibility under the third market framework for making these investments happen.

In addition, given their cross-border nature and the broader benefits and positive externalities they provide as described in the previous section, projects of common interest in particular will often face additional technological or operational risks. Given the additional effort their development implies, operators will be reluctant to enter into the development of these projects. And without adequate return on investment, investors and banks will discard these projects compared to other "standard projects" with a lower but more certain risk-return profile. This will further endanger the timely implementation of the EU's infrastructure priorities.

Some countries have recently introduced – in addition to the existing third market legislative framework (see section 1) – additional incentive schemes in their regulatory framework to promote certain categories of investments. France (for gas) and Italy (for electricity and gas) for example give explicit incentives for congestion reduction and cross-border investments. Some NRAs have also introduced explicit incentives for innovation (UK, Italy).

Member State Incentive Scheme Austria Possible ex-ante consideration of extraordinary investment costs (project specific mark-

up of 0.20% for gas) France Gas: New investments can receive ROR add-on upon decision by the regulator Germany Investment budgets are approved for expansion investments by the regulator upon certain

conditions. After a certain period, the investment budget is transferred into the RAB. Italy Investment premiums of 2%-3% for certain categories of investments Great Britain Specific innovation incentive schemes for low-carbon outputs (e.g. Networks Innovation

Competition, Innovation Allowance, Revenue Adjustment Mechanism, Transmission Investment for Renewable Generation (TIRG))

Netherlands Extra income for substantial investments upon decision by the regulator Portugal Gas: Cost of capital and amortisation are smoothed for the whole concession period (e.g.

40 years). Spain Investment allowances

Table 1: Existing national transmission investment incentive schemes (source: CEER)

However, such mechanisms exist only in certain Member States, remain limited with regard to the types of investment they cover and are only partly in line with the EU's infrastructure priorities.

Finally, it should be noted that investment signals and tariffs are intrinsically linked as the tariff methodology sets the main conditions for the recovery of the investment costs for regulated networks. NRAs decide on cost allocation via the tariff setting in accordance with national preferences, user and network particularities. NRAs will therefore be reluctant to provide by themselves incentives for projects of common interest, which might negatively impact their national customers for the shared and bigger overall benefit of costumers in several other Member States.

3.2.3. Lack of coordination for cross-border investment approval process As projects of common interest will by definition affect at least two Member States, they will require approval of at least two NRAs for the corresponding investment, notably with regard to cost allocation among the two Member States involved. Coordination of procedures on both sides of the border for such approval is crucial to prevent delays or obstacles for the realisation of such projects.

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This is even mort important, as national regulations differ with regard to the way, in which investments are accounted for and remunerated. For the gas sector, the 2009 KEMA study concluded that differences in commercial viability of the same project according to the different national regimes could create a serious barrier to investment: "Investors will compare the return with similar projects in terms of risk and allocate their money accordingly". Concerning specifically open seasons, CEER and the Gas Regional Initiative North-West have underlined difficulties related notably to different regulatory rules applying in different MSs, the uncoordinated launch of open seasons, the lack of transparency due to invoked confidentiality by market operators and the insufficient reliability of the non-binding bidding phase33.

Concerning electricity, experts working on regulatory issues for offshore grid development under the NSCOGI recognised that "the regulatory regimes for offshore transmission are different and may need to become more consistent in future if coordinated development is to be achieved". They noted "notable differences in grid charging regimes and procedures between the countries and these, together with the different levels of renewables support, could lead to developers seeking to locate in areas with low connection charges and high support mechanisms resulting in sub-optimum siting"34.

However, cooperation among NRAs and TSOs for cross-border investments and attempts at coordinating procedures have proved to be difficult and cumbersome, thereby creating delays in project approval and delivery (e.g. Dutch-German or Bulgarian-Greek cooperation in gas or Franco-Spanish cooperation in electricity).35

3.3. Problems related to financing of energy infrastructure projects Energy infrastructure projects are primarily financed by the private sector. Most commonly corporate financing is used: TSOs develop projects with their own capital (balance sheet) and loans from commercial banks and international financial institutions36. Project finance, where the long term financing is only based upon the projected cash flows of the project rather than the balance sheets of the project sponsor, is used only rarely37 (see Annex 13). Moreover, in order to increase their investment capacity, TSOs may seek corporate equity investments from other companies (also from outside the energy sector). Such companies offer additional capital in return for participation in profits generated by the TSO’s projects.

While this system functions rather well in a predictable and stable regulatory environment, there are factors, which make the financing of infrastructures – notably those of cross-border nature targeted by this initiative – difficult38. Financing will be even more challenging for projects with low or no commercial viability, which are often those falling into the categories listed in section 3.2.1. Because of their high economic, social or environmental benefits, public funding would be fully justified to trigger an investment decision for such projects. Nevertheless, the existing support is insufficient both in form and available volumes. The three main factors likely to hinder investments are discussed in the following.

33 CEER, "Monitoring Report 2010 on the compliance with the Guidelines of Good Practice of Open Season

procedures (GGPOS)", Ref: E10-GMM-11-04, 7 December 2010; ERGEG Gas Regional Initiative North-West (GRI NW), "Open Season Coordination", 28 April 2009.

34 NSCOGI Working Group 2, "Report to the Steering Committee", May 2011 35 It should be noted that this impact assessment does not examine in further detail, how different national regulatory

regimes by themselves impact investment decisions and to what extent harmonisation would be beneficial. This question will be addressed under the third package framework (see section 1).

36 TSO equity in projects typically varies between 20% and 100% of the total investment depending on the project risks and scale.

37 As a general rule, if a project lies within the TSO's service area and is mainly linked to domestic transmission or distribution (gas) or uses alternating current technology in a meshed grid (electricity), TSOs will use corporate financing. Project financing, which implies setting up a special purpose company, is used for larger, specific projects such as LNG terminals, storage, merchant lines or complex joint ventures (e.g. mid-stream and some cross-border pipelines) in gas and high-voltage direct current lines or storage in electricity.

38 It should be noted that the financing challenges identified vary between Member States.

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3.3.1. Limited financing capacities of TSOs In view of the scale change in both investment volumes and investment delivery times necessary to deliver on the energy infrastructure priorities until 2020, many TSOs, especially in eastern European Member States, will reach the limits of their financing capacity. The volumes of new investments will exceed the financing possibilities offered by their balance sheet size. Both debt and equity providers have confirmed that, given the levels of available equity, TSOs will face challenges raising sufficient amounts of debt at reasonable cost, especially because of borrowing ceilings or the absence or insufficiency of investment grade ratings, as lenders are not going to accept higher debt/equity ratios. Therefore, certain TSOs could need large equity injections by private investors or public owners to be able to contract more debt for their future investment programmes. Partly or fully state-owned TSOs will depend to a large extent on their government. Given the very difficult budgetary situation of most EU MSs, it is unlikely that they will accept significant equity injections. This is especially handicapping when extensive investment plans exist and TSOs already have a high debt/equity ratio (70/30 or more), as is the case for National Grid or Tennet.

In addition, TSOs are increasingly facing difficulties with accessing long-term debt on favourable terms. Following the financial crisis, banks have reacted with a radical shortening of maturities, increased pricing and collateral requirements. Basel III rules39 will require banks to keep a higher percentage of equity on their balance sheets. Long-term capital commitments for infrastructure projects will become more expensive and difficult to execute. Furthermore, lending conditions have appeared to be insufficiently adapted to project and/or corporate needs of TSOs (loan duration too short, impossibility to make a substantial bullet payment at the end of the loan, limited flexibility, no bridge financing offered between the construction phase and the operational phase)40. As a result, banks will favour less complex and bigger unitary transactions over more complex, innovative or riskier projects. Furthermore, access to EIB loans may become more difficult for certain TSOs41.

These constraints will affect a TSO’s ability to deliver on its overall investment programme (including infrastructures of European and of solely national relevance). PCIs will have to compete for investment budget with national priorities. Given the increasing constraints on lending capacities, bond markets to raise larger debt volumes could play an increasingly important role in the coming years. However, issuing bonds implies that TSOs have a solid credit rating. Today, however, about 40% of TSOs in Europe (gas and electricity) are not rated42 and therefore have no access to funding from bonds and private placements. As energy networks are regulated, an increase in tariff levels for energy consumers could be an alternative way to raise capital to finance new investments. However, there are important social and political limits to increasing tariffs (see chapter 10).

3.3.2. Difficulties for energy infrastructure investments to attract new institutional investors Institutional investors such as pension funds, insurance companies and wealth funds are increasingly moving into infrastructure investment given its potential to match long-term assets and provide diversification. The stability provided by the regulated model corresponds to pension funds’ investment profile, characterized by relatively low rates of return – around 7%-8%43 – and long investment horizons. These investors are also becoming increasingly ready to invest directly in infrastructure assets. This is new, as their exposure to infrastructure has traditionally been via listed

39 The Basel III global regulatory standard will come into force in 2013. It strengthens bank capital requirements and

introduces new requirements on bank liquidity and bank leverage. 40 Roland Berger, 2011a. 41 Loans from the EIB are seen as the most important component of debt financing by many TSOs, especially smaller

TSOs in Eastern Europe. Many TSOs have reached limits with regard to how much unsecured lending they can receive from the EIB. As a general principle, the EIB aims at not providing more than 10% of unsecured lending compared to a TSO's equity. In the EU15 TSO sector, the EIB already is often already above this ceiling. In most EU12 Member States however, the EIB does not yet agree to higher unsecured lending and requires bank or state guarantees.

42 Roland Berger, 2011a. 43 Compared to 10%-12% infrastructure funds typically offer their investors. Source: InfraNews, “How Real a Threat

to Infra Funds is the Direct Investing Phenomenon?” 24 May 2011.

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companies (such as utilities), or via real estate portfolios44. Their role as financiers for TSOs and dedicated infrastructure project companies is therefore expected to rise.

However, the arrival of such new classes of investors, which might have different expectations concerning the risks incurred compared to current regulatory practice, may require regulatory adaptations. Furthermore, there need to be investment opportunities available, i.e. equity opened to participation and/or debt products. The fact that to date only some TSOs are fully open to equity investment from third parties, given their ownership structure (see Annex 13, Figure 16 and 17), limits the inflow of capital from institutional investors and will not help to ease the investment challenge in the short to medium term.

3.3.3. Lack of adapted funding instruments and sufficient envelopes The 2010 impact assessment already described the available financing under the existing TEN-E programme (in its Annex 2) and its shortcomings (notably limited budget, inflexibility, no risk mitigation instruments, no funding outside the EU, insufficient synergies with other EU funds). It also highlighted the positive contribution made by the European Energy Programme for Recovery45, which has responded to some of the weaknesses identified, but was a one-off exercise.

In addition, energy infrastructrures today can benefit from the support of Structural and Cohesion Funds. Under the 2007-2013 budget, EUR 1.6 bn have been allocated to Member States for projects classified as TEN-E. However, available funds have seen only a slow uptake by Member States. The programming approach makes it less flexible to shift funds between projects and programmes, even if they are seen as particularly relevant from the EU energy policy perspective at a certain point of time. The funds are not centrally managed, which makes it difficult to coordinate across and between countries to ensure the regional network benefits of investments.

European energy infrastructures can also benefit from grant support under the EU research programmes. Such support is important from the technology development and demonstration perspective, but it does not contribute directly to the construction of industrial-scale projects.

The table below summarises the financial efforts at EU level to support the development of energy infrastructures during the current financial period (2007-2013).

Funds allocated within financial perspective 2007-

2013 Funds spent/committed 2007-2009

Gas infrastructure

Electricity infrastructure

Electricity and gas infrastructure Studies Works Studies Works

EIB 3 500 – 7 000 - 3 407 - 2 561 IFI EBRD - - - 488 TEN-E 155 22 7 23 18 EEPR 2 268 11 1 352 2 903

Structural Funds 1 607 24 8

EU

RTD Framework Programme

150 - - 50 -

Total IFI and EU funds 7 680 – 11 180 4 823 4053

Table 2: Total funds (loans and grants) from EU institutions allocated to electricity and gas infrastructure within financial perspective 2007-2013 (* EEPR: Some infrastructure projects related to works include studies) 44 OECD, "Pension Fund Investment in Infrastructure", Working Paper on Insurance and Private Pensions, January

2009. 45 Regulation (EC) No 663/2009 of the European Parliament and of the Council of 13 July 2009 establishing a

programme to aid economic recovery by granting Union financial assistance to projects in the field of energy (OJ L200, 31.7.2009)

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The range of financial tools available at EU level to promote projects of common interest is for the moment effectively limited to grants. There are no specific “innovative financial instruments”, which would support projects in a different manner than just by reducing the initial capital expenditure for investors. There is no possibility to provide risk capital to projects46. There are also no risk sharing arrangements, through which the Commission could enable financial institutions to provide sector specific lending facilities (loans on adapted terms, guarantees, facilitation of direct market (bonds) financing)47 addressing the risks of specific projects. The existing tools do not allow for using the EU budget to accelerate project preparation by e.g. providing start-up capital.

With a growing number of complex and cross-border projects of European importance, well designed equity or debt instruments would be likely to assist them in facilitating access to equity and/or debt finance, reducing the cost of capital, adapting lending conditions to better match project cash flows and facilitating project finance structuring through standard equity and debt instruments. It is also essential to note that such form of support would come at a lower expense to the public budget (higher leverage)48. It should however be noted that innovative financial instruments will never be the remedy for all types of projects, especially if project financing is a prerequisite. Such instruments can only be used for projects which generate sufficient revenues to repay their debts and remunerate for financial support received – hence the need for the commercial viability of projects.

4. BASELINE SCENARIO This chapter looks at how energy infrastructures would develop over the coming decades, should no further policy actions be taken. It builds on the chapter "Baseline scenario" of the 2010 impact assessment, which presented the methodology used for the energy infrastructure needs assessment and analysed the resulting energy trends and infrastructure needs. The findings of this chapter are not repeated here. In the following, we do however, on the basis of a detailed assessment of the current policy framework in Annex 14, analyse how much and which type of infrastructure would be delivered and which one not, if no further action was taken. This allows us to refine the analysis of investments at risk of not being delivered when needed ("investment gap" in the 2010 impact assessment).

As already highlighted in the 2010 impact assessment and as described in the previous section, the current planning, permit granting, regulatory and financing framework for energy infrastructure development will lead to significant under-delivery of infrastructures under business as usual (BAU).

Insufficient top-down prioritisation and cross-border planning will not allow focussing attention on those infrastructures, which bring the highest value added in view of reaching the 2020 energy policy targets. As a result, there is a high risk of projects of common European interest not receiving the political attention they need to be pushed trough by 2020.

Persistent delays due to complex and lengthy permit granting procedures and low public acceptance will further delay new infrastructure projects, notably in electricity. Under business as usual, the real duration of the statutory authorisation procedure would continue to vary between less than 2 years and 10 years depending on the Member States, with an average of about 4 years (see Annex 7). In many Member States, public resistance to new infrastructure projects would increase this duration by a significant amount of years due legal recourse procedures. The efforts associated with

46 The Marguerite Fund, to which both the Commission and the EIB have contributed, is expected to invest also in

energy projects. However, the high yield expectation is likely to exclude typical energy transmission projects. 47 Such risk sharing instruments have already been developed for other sectors. Since more than ten years, the EU

budget has been using financial instruments. Under the 2007-2013 financial framework, a new generation of financial instruments has been put in place in cooperation with the EIB, such as the Risk-Sharing Finance Facility (RSFF) under the 7th R&D Framework Programme, or the Loan Guarantee Instrument for TEN-T projects (LGTT). Although fragmented, experience until now with financial instruments has been positive in these sectors. Court of Auditors' reports have generally praised the effectiveness of these instruments, with exceptions in certain cases.

48 Market based/innovative instruments are characterised by a higher leverage (in comparison to grants) and their potential to generate revenue for the body that provides them (unlike grants, they do not come for free)

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the permit granting procedure could exceed 10% of total project costs49, thereby also increasing the investment and the overall electricity system cost and binding resources, which could be used more efficiently for the actual investments necessary in grid infrastructure.

In line with the results of the 2005 "TEN Energy Invest" study already presented in the 2010 impact assessment, the ratio “performed investments” on ”scheduled investments” in electricity could be as low as 50% for the coming decade, given the increased levels of local opposition and associated media focus on certain projects since 200550. This business-as-usual scenario can be compared to the planning presented in the 2010 electricity TYNDP: Despite conservative estimates for commissioning dates, almost 30% of all projects identified foresee completion in or after 2020 or have not set a commissioning date at all. This applies in particular to 35 transboundary projects listed in the 2010 TYNDP.

Applying these results to the total investment needs in electricity of EUR 100 bn (excluding smart grid investments), it can be estimated that up to EUR 50 bn worth of projects could be subject to delays beyond 2020 and jeopardize the efforts of the EU to meet the Union's 2020 energy and climate objectives. This number has been largely confirmed by national regulators51.

Concerning requirements set by environmental legislation, an analysis of the current TYNDP showed that about 20 projects may face difficulties due to conflicts with Natura2000 areas. EU environmental legislation leaves substantial flexibility to the MS competent authorities to solve the conflicting objectives between security of supply and renewables integration and the protection of the local wild life. If these conflicts are not satisfactorily solved, some of these energy infrastructure projects may be not be delivered.

Nationally focused regulation, lack of cost allocation solutions and difficult coordination between NRAs and TSOs would further delay the realisation of projects with cross-border impacts and increasingly asymmetric costs and benefits. This will particularly affect the implementation of the identified infrastructure priorities, which are mainly based on cross-border or even regional projects. Insufficient risk-related incentives in line with policy objectives could lead to lock-in situations with infrastructures, which in the short term contribute to energy and climate policy objectives (e.g. emission savings) but generate fewer benefits in view of longer term objectives.

Concerning electricity interconnectors, between 2000 and 2011, about 30 cross-border electricity projects involving EU Member States have been commissioned, out of which 25 concerned new lines (see list in Annex 15). By comparison, the 2010 TYNDP foresees a total of 76 cross-border projects, out of which 58 projects concern new lines for a total value estimated by the Commission at over EUR 31 bn. In the absence of new cost allocation rules, it is unlikely that existing regulation and new measures described above alone will allow completing the internal market, while adapting effectively to the fast rising electricity flows from variable renewable generation and the ensuing needs for balancing and storage capacities, in a context of rapidly changing national energy policies52. This could also endanger the reliable operation of the European electricity grid as a whole53. Assuming a business-as-usual development pace, only about 25 out of the 58 needed interconnectors can be expected to be online by 2020. This would leave about 30 projects or EUR 16 bn at risk.

49 This estimation is based on empirical data provided by various TSOs. 50 The ratio is even lower in the case of Germany: The 2010 DENA network study II identifies a need of grid

extension of 3,500km between 2015 and 2020. A first DENA study in 2005 had estimated a need of 850km, of which less than 100km have so far been completed.

51 "The CEER survey suggests that the volume of investments being delayed due to planning procedures, licensing and lack of public acceptance is likely to be significantly higher [than EUR 40 bn, the initial Commission estimate]." ("European Infrastructure Package: Investment needs and financing mechanisms – Financing Task Force conclusions", reference C11-FTF-02-01, 23 March 2011).

52 Following the tsunami and ensuing nuclear accident at Fukushima (Japan) in March 2011, Germany decided in June 2011 to phase out its nuclear power generation capacities by 2022, while a referendum in Italy reverted a previous decision to develop new nuclear power plants. Several other Member States are currently reconsidering their approach to nuclear approach. This will have important consequences on the electricity mix until 2020 and beyond, with corresponding impacts on the need for additional electricity and gas transmission infrastructure.

53 Certain Central European operators in particular are warning about massive electrical power flows of insufficient control, which could lead to bulk outages of supply and, under extreme conditions, even a total blackout.

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Concerning more specifically offshore grids in the Northern Seas, under business-as-usual with merely national regulatory frameworks and without general cost allocation rules or risk-related incentives, internationally optimised solutions – including direct connection of wind farms to international interconnectors or interconnectors between two wind farm hubs – will not be developed, while radial solutions will continue to be the preferred option of TSOs connecting new individual wind farms54. This would affect roughly EUR 10 bn out of a total investment of EUR 30 bn foreseen up to 2020 and prevent offshore grids from starting to develop into a meshed network already by 202055, increasing long-term costs and preventing optimal renewables and market integration at European level, also in view of developing a continental electricity highways system.

Concerning innovative investments in electricity storage and smart grids, it can be expected that these will progress only at slow pace under BAU, given the risks inherent to such projects, the uncertain allocation of costs and benefits and the insufficiency of existing incentives. With regard to smart grids in particular, failure to act at EU level might also lead to insufficient integration of large-scale renewables capacities and deployment of electric vehicles as well as lack of regional cross-border demand-supply optimisation. As a result, peak demand in electricity could be up to 5% higher by 2020 and up to 8% by 2030 respectively56, with corresponding needs for investment in expensive peak load and back-up generation assets.

With regard to gas networks, the years 2000-2011 saw considerable development of new storages and LNG terminals with an upward trend throughout the period. Gas interconnectors, linking EU regional gas markets, however, have only developed slowly. While several new import pipelines are successfully coming online in the North and South of the EU, only 4 new gas interconnectors were built in the past decade. The EEPR support has had a significant impact in accelerating major interconnector investments in 2011 (PL-CZ, HU-CR, RO-HU). Other projects were and are being delivered on the basis of exemptions (see Annex 15).

Concerning planned future investments, the 2011 TYNDP considers higher investment needs of EUR 89 bn for the period 2011-2020 than those estimated in the 2010 impact assessment (EUR 70 bn). Projects worth about EUR 67.8 bn have not received a final investment decision (FID) yet, although they will, according to ENTSOG, contribute most to enhancing security of gas supply, creating flexible gas networks for market integration and linking isolated regions. Most of them are cross-border (EUR 58 bn). Currently planned FID projects, notably in storage, will only address additional demand under severe weather conditions (see Annex 15). It can therefore be concluded that under a business-as-usual development scenario and in the light of past investments, the value of projects at risk of not being delivered could be significantly higher than the EUR 10 bn estimated in the 2010 impact assessment, in particular with regard to interconnectors.

Concerning CO2 transportation, as already explained in the 2010 impact assessment, most of the potential EUR 2.5 bn investment needed over the period 2010-2020 will not be delivered under business-as-usual.

Business as usual would also mean the continuation of the current TEN-E approach to financing, with limited amounts of EU funding focussed on studies rather than works57 and no reiteration of the

54 The Dutch-German grid operator TenneT, which as of March 2011 had over 7 GW of offshore wind farm

connection projects ongoing or planned in the German North Sea, indicated regulatory clarity among the key challenges for the feasibility and commercial viability of its projects. Operators in the United Kingdom have also indicated that the current round 3 tender process for offshore wind farm developments could lead to uncontrolled point-to-point connections onshore without overall optimisation, e.g. by developing integrated hub-and-spoke grid designs, as the latter involve too high and risky investments. This could lead to increased costs and difficulties for onshore onwards transmission on already fully used networks. NRAs have argued that hub solutions could develop in certain Member States of the NSCOGI from 2015 onwards. Results from the OffshoreGrid study show however that "teeing in", i.e. directly connecting wind farms into an interconnector, or linking two wind farm hubs in two different Member States through an interconnector makes socio-economic sense in many cases, notably if the concerned wind farms are far from shore.

55 Commission estimation, based on OffshoreGrid study results. 56 Source: IEA, April 2011 57 In the 2007-2009 period, about 65% of the allocated TEN-E funds were dedicated to studies (45M€), while 35%

went to works (25M€).

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European Energy Programme for Recovery. As a result, projects of European significance would continue to mainly receive EU grants for feasibility and front-end engineering and design studies. Financial support for the construction of projects would remain very limited: An expected EUR 55M of the available funds of EUR 155M would cover works expenses. In addition, EU allowed co-financing rates for works would continue to be insufficient to boost the implementation of certain projects. Indeed, as demonstrated by the EEPR experience, for projects aiming at increasing security of supply, a co-financing rate of 50% or more can be necessary to unblock the project while the current TEN-E co-financing rate is capped at 10% of the construction costs58. As a result, only investments with a sufficiently high direct and short-term benefit for the investor(s) would be realised, which would be insufficient to meet the challenge arising from the step change in investments59.

Concerning the other contributions to infrastructure financing, it can expected that the EIB lending trends to energy grid projects observed over the last couple of years would not be maintained. While the EIB's lending volume to the energy infrastructure industry rose from EUR 2.5 bn in 2007 to EUR 6 bn in 2010 (with about EUR 3 bn for energy transmission and EUR 3 bn for energy distribution), the EIB Board of Governors has made it clear that it did not wish for extended EIB lending towards energy grid infrastructures, with lending volumes returning to pre-crisis levels, i.e. decreasing by roughly one third compared to their peak in 2010. Depending on the evolution of macroeconomic conditions and the speed of economic recovery in EU economies, this downside effect could be partly compensated by a renewed interest from commercial banks in lending to regulated, risk-free activities.

On the equity side, equity capital provision will continue to be dominated by government involvement, as a large number of European TSOs have public institutions as their majority shareholders. This will limit the potential involvement of external shareholders, leaving internal equity stemming from the TSO's own operational revenues as the main source of basic financing for future infrastructure investments. However, given the strong constraints on public finances for the coming years, it can be expected that, where external equity investments are feasible, such equity injections will be sought as an alternative. However, it might prove difficult for the TSO sector to attract sufficient amounts of such investments, given the profile of relatively low returns (less than 10%) for low risks.

In any case, even if there were sufficient debt and equity funds available under business as usual to meet the EUR 210 bn investment challenge, these market-based funds will not be sufficient to deliver the more complicated types of projects discussed above. But with a mere continuation of EU grants made available during the 2007-2013 period (excluding the EEPR) and given the likely future evolution of (repayable) loans provided by financial institutions, far less than EUR 2 bn of (non-research) grants would be available for the period after 2013 up to 2020 under business-as-usual. This amount will be severely insufficient to satisfy the funding needs expected, given the identified investments and their urgency until 2020.

As a result of these trends of the baseline scenario, the Commission estimates that a significant share of the needed investment of approximately EUR 200 bn until 2020 will not be delivered on time under the existing framework. This will make the achievement of the EU's energy and climate policy objectives in terms of renewables deployment and emission reduction by 2020 impossible, but it will also seriously hinder market integration, diversification and security of supply. Lack of interconnections will reduce opportunities for system optimisation, increase the risk of disruption and trigger additional costly back-up and balancing generation investments. Supplying energy and balancing supply and demand will become more expensive, with the corresponding effects on the competitiveness of European industries, consumers and growth.

58 Grants, however, would not provide always the right incentives to invest. Indeed, as mentioned in Chapter 2

Article 109 of the EU financial regulation, grants may not have the purpose or effect of producing a profit for the bene